In recent years, the use of downhole rotary pumps driven by rotating rod strings has enabled the production of oilwell fluids containing considerable quantities of entrained sand. However, the rotating rod string contacts and wears the wall of the tubing string. The sand in the fluid makes the wear more severe, which in the worst case results in formation of a hole. Use in a slant hole further encourages the rod string to lay on the tubing wall, aggravating the wear.
Assemblies which slowly rotate the tubing have been known since the 1950's as a means to distribute the wear, thereby prolonging the life of the tubing string. Generally, prior art tubing rotators commonly comprise the following components:
--a generally tubular housing adapted for connection to the casing bowl flange of a wellhead; PA1 --a hollow drive shaft which extends down through the housing and is connected at its lower end to the tubing string; PA1 --the drive shaft being rotatably supported from the housing with a thrust bearing; and PA1 --a drive means extending into the housing, said drive means having a gear attached to the drive shaft, for rotating the drive shaft and the attached tubing string. PA1 --the upper end of the annulus of the well is temporarily open when the housing is unbolted and lifted; PA1 --the lifting of the tubing string can disturb sand in the annulus at the base of the tubing string; and PA1 --the formation may then produce the "kick", sending fluid upwardly through the annulus at a time when there is no closure or seal at the top of the annulus. PA1 --a capability for removing the tubing rotator housing without lifting the tubing string; PA1 --a capability to install the BOP after removal of the housing while maintaining closure of the annulus; and PA1 --a capability to pull the remaining tubing rotator related components through the BOP with the tubing string. PA1 --a swivel dognut assembly, having a stationary outer sleeve adapted to be substantially contained within the casing bowl bore, to be suspended from the tapered portion of the bore surface and to seal against the inner surface of the casing bowl, said outer sleeve supporting bearing means on its inner surface, said assembly having an inner sleeve seated on the bearing means so that the inner sleeve is rotatably supported by the bearing means and outer sleeve; PA1 --said inner sleeve being connectable at its lower end to the tubing string; PA1 --holddown means being operative when engaged to restrain the outer sleeve to the casing bowl, to prevent vertical upward displacement; PA1 --a generally tubular housing being connectable to the casing bowl flange; PA1 --drive means, associated with the housing, for rotating the inner sleeve; and PA1 --as a preferred feature, disengagable means for locking the inner and outer sleeves together so that the housing and part of the drive means can be disconnected and removed from the casing bowl while the tubing string and swivel dognut assembly remain restrained in the casing bowl to seal the annular space formed between the tubing string and the well casing, whereby a BOP may be lowered over the first means to engage the casing bowl.
The prior art is typified by assemblies disclosed by U.S. Pat. No. 2,696,238, issued to Baker and by the publications and products of Rotating Production Systems, Inc., of Denver, Colo., specifically the Rotating Tubing Hanger model LRH-1S/HD.
The Rotating Production Systems' assembly embodied in model LRH-1S/HD rotates the drive shaft with a single worm which extends into the housing to driveably engage a drive shaft-mounted ring gear. The rotating drive shaft and suspended tubing string are supported from the housing. The drive shaft extends upwards through the housing for connection to a swivel, which enables connection to the non-rotating wellhead components. The swivel is an inherently weak assembly. Further, the drive shaft and swivel protrude from the housing, significantly increasing the height of the wellhead components.
The Baker assembly uses a manual barring technique to rotate the drive shaft. The non-rotating wellhead components are secured to the housing.
Several disadvantages are associated with both of the Baker and Rotating Production Systems assemblies.
Of greatest significance is the risk of a blowout when wells fitted with these tubing rotators are serviced. Servicing the well requires removal of the rod and tubing strings. Even though the well is "killed" by filling it with heavy fluid prior to servicing, there is a risk of a "kick" associated with removing the tubing string. The gas pressure in a subsurface formation may build up and eject or "kick" the fluid out of the wellbore. It is a standard safety procedure to mount a blowout preventer (BOP) to the casing bowl during servicing. The tubing string is subsequently pulled out through the BOP.
In the assemblies of Rotating Production Systems and Baker, the tubing string is suspended from the housing. When the well is to be serviced, one must begin by unbolting the housing from the casing flange. The housing and suspended tubing string are then lifted upwardly and supported on a set of slips. The housing, the hollow shaft and the rotary drive assembly are then removed. This procedure is characterized by the following disadvantages:
With the foregoing in mind it is desirable to provide a tubing rotator having the following characteristics:
In addition, it is desirable to provide a tubing rotator that is compact and does not protrude above the casing bowl to the extent that the prior art assemblies do.